General Thoughts, page-7668

Here, some data and infos are confirmed for Venus now:
Reservoir thickness of 80-120 m is good.
Permeability of 2-4 mDarcy is not so good for a conventional oil field. This would be ok for a gas field but here we move to a tight oil reservoir (not good)
The density is 45 API that is compareable to Diesel (is good). And in an interview we heard that this oil got a low viskosity (is good). This reservoir with this low perm can only work because the viscosity ist so low.
Production rate is influenced by thickness times permeability (h x k is important when you compare reservoirs for example) and viscosity.
Additional we need a driving force. This will be probably gas expansion drive. Gas expansion drive is not very effective for the oil recovery factor and Total and Shell see this as cost factor when they are not allowed to flare the produced gas.
Till now I have not seen any hints for an active aquifer and it is expected that one day in the future you need water injection to get a better recovery factor. But with this low perm this can be a problem in the future.
I understand that Total is happy with the discovery but this discovery is not perfect, because mainly the permeability is on the lower end. Shell did not give up Namibia but I think for Shell the Graff block is not anymore their number one block in the global ranking because of low perm.

Currently Irak is celebrating because they just discovered a new oil field with 2 billion bbl oil reserves (=producible) and tested with 5.000 bbl/d. See: https://jpt.spe.org/iraq-discovers-mega-oil-field-near-baghdad?

Now lets have a look to Mopane with 10 or more billion bbl in place (perhaps you can produce 25-35 % (I am conservative and I do not say 45% because of the low permeability???) . And Mopane has a test rate of 15.000 bbl/d constrained. But keep in mind that you do not get such a good test rate from a low perm or tight oil reservoir. This could be a hint that recovery could be higher than perhaps 25%.

When we move now to Saturn. For the volume of the oil in place I am optimistic that 40 billion bbl oil in place is possible because of the geology and seismic we have seen and got explained by oldgeo &jibby & V10 and ...(thanks). (There is always risk till to to the very end in oil and gas exploration. For example the Saturn, Oryx could be full with reservoir water instead of with oil...). For the final proof we need the drill bit (and thats the reason I do not like that Woodside is still moving like a snail) and we need to hit a sweet spot in Saturn to get something like a +15.000 bbl/d production test rate.

PS some users wrote that EOR=tertiary production is done off shore. This I did not read in the books during my education and I did not see this during my work life. Perhaps I am getting old and out dated? Please send me your literature sources that I can learn. By definition you have primary production like an eruptive well, secondary production when you inject water to maintain reservoir pressure (secondary means you improve reservoir pressure) and tertiary production when you inject for example steam to change the viscosity of the oil or inject polymeres to change the viscosity of the water for water flooding (tertiary means you change something else like viscosity in the reservoir) In Namibia for Shell and Total it is already too expensive to process the gas during primary production. Secondary production is more expensive and tertiary production is the most expensive way of production.